Improving the efficiency of hydraulic fracturing treatment in CBM reservoirs by stimulating the surrounding natural fracture system

A method is proposed for enhancing the conductivity of micro-fractures and cleats around the hydraulically induced fractures in coal bed methane reservoirs. In this technique, placing ultra-fine proppant particles in natural fractures and cleats around hydraulically induced fractures at leak-off conditions keeps the coal cleats open during water-gas production, and this consequently increases the efficiency of hydraulic fracturing treatment. Experimental and mathematical studies for the stimulation of a natural cleat system around the main hydraulic fracture are conducted. In the experimental part, core flooding tests are performed to inject a flow of suspended particles inside the natural fractures of a coal sample. By placing different particle sizes and evaluating the concentration of placed particles, an experimental coefficient is found for optimum proppant placement in which the maximum permeability is achieved after proppant placement. In the mathematical modelling study, a laboratory-based mathematical model for graded proppant placement in naturally fractured rocks around a hydraulically induced fracture is proposed. Derivations of the model include an exponential form of the pressure-permeability dependence and accounts for permeability variation in the non-stimulated zone. The explicit formulae are derived for the well productivity index by including the experimentally found coefficient. Particle placement tests resulted in an almost three-times increase in coal permeability. The laboratory-based mathematical modelling, as performed for the field conditions, shows that the proposed method yields around a six-times increase in the productivity index.

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Development of a new approach for hydraulic fracturing in tight sand with pre-existing natural fractures

The APPEA Journal ◽

10.1071/aj15017 ◽

2016 ◽

Vol 56 (1) ◽

pp. 225 ◽

Cited By ~ 7

Author(s):

Kunakorn Pokalai ◽

David Kulikowski ◽

Raymond L. Johnson ◽

Manouchehr Haghighi ◽

Dennis Cooke

Keyword(s):

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

High Stress ◽

Gas Production ◽

Natural Fracture ◽

Rock Properties ◽

Fracture Plane ◽

Natural Fractures ◽

Geomechanical Model ◽

Well Design

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.

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Numerical Investigation of the Fracturing Effect Induced by Disturbing Stress of Hydrofracturing

Frontiers in Earth Science ◽

10.3389/feart.2021.751626 ◽

2021 ◽

Vol 9 ◽

Author(s):

Xinglong Zhao ◽

Bingxiang Huang ◽

Giovanni Grasselli

Keyword(s):

Shear Stress ◽

Fracture Surface ◽

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

Shear Failure ◽

Fluid Pressure ◽

Natural Fracture ◽

Coal Bed ◽

Natural Fractures ◽

Fracture Failure

Fracturing induced by disturbing stress of hydraulic fracturing is the frontier common core scientific problem of reservoir stimulation of coal bed methane and shale gas. The finite-discrete element method, numerical calculation method, is used to analyze the basic law of shear failure and tension failure of natural fractures induced by the disturbing stress of the hydraulic fracture. The simulation results show that when natural fractures and other weak structures exist on the front or both sides of hydraulic fracture, the shear stress acting on the surface of natural fracture will increase until the natural fracture failure, which is caused by the disturbing stress of hydraulic fracturing. The seepage area on the front and both sides of the hydraulic fracture did not extend to the natural fracture while the natural fracture failure occurred. It indicates that the shear failure of natural fractures is induced by the disturbing stress of hydraulic fracturing. When the hydraulic fracture propagates to the natural fracture, the hydraulic tension fracture and disturbed shear fractures are connected and penetrated. As the fluid pressure within the natural fracture surface increases, the hydraulic fracture will continue to propagate through the natural fracture. Meanwhile, due to the action of fluid pressure, a tensile stress concentration will occur at the tip of the natural fracture, which will induce the airfoil tension failure of the natural fracture. With the increase of the principal stress difference, the range of the disturbing stress area and the peak value of the disturbing stress at the front of the hydraulic fracture tip increase, as well as the shear stress acting on the natural fracture surface. During the process of hydraulic fracture approaching natural fracture, the disturbing stress is easier to induce shear failure of natural fracture. With the increase of the cohesive force of natural fracture, the ability of natural fractures to resist shear failure increases. As the hydraulic fracture approaches natural fractures, the disturbing stress is more difficult to induce shear failure of natural fracture. This study will help to reveal the formation mechanism of the fracture network during hydraulic fracturing in the natural fractures developed reservoir.

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Study of Cyclic Fracturing in Vertical CBM Wells

The Open Petroleum Engineering Journal ◽

10.2174/1874834101710010108 ◽

2017 ◽

Vol 10 (1) ◽

pp. 108-117 ◽

Cited By ~ 2

Author(s):

Ting Li ◽

Ji-fang Wan

Keyword(s):

Hydraulic Fracturing ◽

Economic Benefits ◽

Natural Fracture ◽

Coal Bed ◽

Coal Bed Methane ◽

Plastic Behavior ◽

Natural Fractures ◽

Stimulated Reservoir Volume ◽

Reservoir Volume ◽

Coal Rock

Background:Coal-bed methane productivity of single well is very low, and has been the bottleneck of the coal-bed methane industry in China.Objective:Although hydraulic fracturing is the only stimulation measure to develop CBM, it cannot increase production effectively, conventional fracturing method to create opening fractures should be improved. How to make good use of natural fractures, which are plentiful in CBM reservoirs, is also an important subject for hydraulic fracturing.Method:In this paper, the plastic deformation of coal rock is analyzed by harnessing a pseudo-Maxwell creep phenomenon, which is normally present in rock. The Kelvin-Voigt model is utilized to describe pseudo-plastic behavior of coal rock to determine pressurization and decay cyclic time for cyclic fracturing design. The mechanical requirement for shearing natural fractures is also analyzed, and shearing distance between the faces of natural fracture can be calculated by Westergaard stress function. Ultimately, the cyclic fracturing method is proposed according to theories about stress alteration and shearing of natural fractures. This method includes such periods as fracturing, pumping shut-down and so on.Conclusion:A complex fracture system can be created, which consists of opened and sheared fractures, then, large SRV(stimulated reservoir volume)and flowing drainage area can be acquired. In comparison with conventional fracturing method, this new way can make full use of the characteristics of CBM reservoirs and is more suitable to CBM. This method will lead to a significant increase of CBM production, and will achieve huge economic benefits.

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A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00980-8 ◽

2020 ◽

Vol 10 (8) ◽

pp. 3333-3345

Author(s):

Ali Al-Rubaie ◽

Hisham Khaled Ben Mahmud

Keyword(s):

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

Natural Fracture ◽

Shear Stresses ◽

Individual Element ◽

Natural Fractures ◽

Gas Reservoirs ◽

Stimulated Reservoir Volume ◽

Reservoir Volume ◽

Naturally Fractured

Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.

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A Peridynamics Model for the Propagation of Hydraulic Fractures in Heterogeneous, Naturally Fractured Reservoirs

10.2118/spe-173361-ms ◽

2015 ◽

Author(s):

Hisanao Ouchi ◽

Amit Katiyar ◽

John T. Foster ◽

Mukul M. Sharma

Keyword(s):

Hydraulic Fracturing ◽

Hydraulic Fracture ◽

Fracture Propagation ◽

Two Dimensions ◽

Natural Fracture ◽

Hydraulic Fractures ◽

Natural Fractures ◽

Fracture Networks ◽

Complex Fracture ◽

Nonlocal Continuum Theory

Abstract A novel fully coupled hydraulic fracturing model based on a nonlocal continuum theory of peridynamics is presented and applied to the fracture propagation problem. It is shown that this modeling approach provides an alternative to finite element and finite volume methods for solving poroelastic and fracture propagation problems and offers some clear advantages. In this paper we specifically investigate the interaction between a hydraulic fracture and natural fractures. Current hydraulic fracturing models remain limited in their ability to simulate the formation of non-planar, complex fracture networks. The peridynamics model presented here overcomes most of the limitations of existing models and provides a novel approach to simulate and understand the interaction between hydraulic fractures and natural fractures. The model predictions in two-dimensions have been validated by reproducing published experimental results where the interaction between a hydraulic fracture and a natural fracture is controlled by the principal stress contrast and the approach angle. A detailed parametric study involving poroelasticity and mechanical properties of the rock is performed to understand why a hydraulic fracture gets arrested or crosses a natural fracture. This analysis reveals that the poroelasticity, resulting from high fracture fluid leak-off, has a dominant influence on the interaction between a hydraulic fracture and a natural fracture. In addition, the fracture toughness of the rock, the toughness of the natural fracture, and the shear strength of the natural fracture also affect the interaction between a hydraulic fracture and a natural fracture. Finally, we investigate the interaction of multiple completing fractures with natural fractures in two-dimensions and demonstrate the applicability of the approach to simulate complex fracture networks on a field scale.

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Integration of outcrop, subsurface, and microseismic interpretation for rock-mass characterization: An example from the Duvernay Formation, Western Canada

Interpretation ◽

10.1190/int-2017-0156.1 ◽

2018 ◽

Vol 6 (4) ◽

pp. T919-T936 ◽

Cited By ~ 2

Author(s):

Mason K. MacKay ◽

David W. Eaton ◽

Per K. Pedersen ◽

Christopher R. Clarkson

Keyword(s):

Rock Mass ◽

Hydraulic Fracturing ◽

Distinct Element ◽

Integrated Approach ◽

Natural Fracture ◽

Western Canada ◽

Natural Fractures ◽

Data Set ◽

Fracture Geometry ◽

Rock Mass Characterization

Identifying and characterizing geomechanical domains is important for understanding how a reservoir will respond to hydraulic fracturing, including interaction with natural fractures to create new permeable pathways. We have used a rock-mass characterization approach, which describes the mechanical reservoir package by combining parameters of the intact rock, such as brittleness, with inferred geometry and density of natural fractures. Insights from outcrop observations are important to complement the interpretation of fracture geometry and density derived from subsurface data, to give a more complete understanding of natural fracture networks. This integrated approach is applied to a data set from the Duvernay play in Western Canada. A synthetic model of the subsurface reservoir is constructed using data from well logs, cores, and outcrop analogs. Numerical simulation of the response of the artificial rock mass to hydraulic fracturing is performed using a distinct element code. Independent validation of the model is obtained by achieving an agreement between the simulated microseismic response and the observed distribution of microseismicity during hydraulic fracturing.

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Hydraulic Fracturing at Clair: Unlocking the Potential of Europe's Largest Reservoir

10.2118/205250-ms ◽

2022 ◽

Author(s):

Alistair Malcolm Roy ◽

Graeme Henry Allan ◽

Corrado Giuliani ◽

Shakeel Ahmad ◽

Charlotte Giraud ◽

...

Keyword(s):

Hydraulic Fracturing ◽

Phase 1 ◽

Poor Quality ◽

Natural Fracture ◽

Hydraulic Fractures ◽

Production Test ◽

Natural Fractures ◽

The South ◽

Initial Development ◽

Matrix Quality

Abstract The Greater Clair area, Europe's largest oilfield, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with future potential for a third platform targeting undeveloped Lower Clair Group to the South of Ph1. Clair Phase 1 was the initial development of Clair, targeting Lower Clair Group (LCG) reservoir consisting of a complex Devonian sandstone in six units. Most Phase 1 wells penetrated relatively good quality reservoir enhanced by natural fractures, while more recently Clair Ridge wells took a similar approach targeting natural fractures, however that strategy is continually being evaluated. In some areas however low matrix quality and lack of natural fractures were the dominant characteristics resulting in lower production rates. A brief comparison of the range of production outcomes will be presented, including potential downsides of reliance on natural fractures. Given the large oil volumes in areas of known poorer rock quality, alongside variable production results, a hydraulic fracturing trial was initiated in 2017. Well 206/08-A23 (A23) targeted previously under-developed, poor-quality Unit VI within the Phase 1 Graben area where natural fractures are absent. A pre-frac production test established baseline production of 900BOPD in December 2018. The A23 objectives included subsequent hydraulically fracturing the well to test this techniques ability to unlock production from tight, matrix dominated formation. Detailed analysis of core, log and limited vertical well fracturing data (from initial fracturing trials of 1980's vintage), yielded robust designs. Key challenges included overcoming very low KV/KH ratios with fracture heights exceeding 300ft. The resulting detailed designs provided consistent and predictable hydraulic fracturing execution in A23 in 2019, including placement of four planned 500klbs treatments combined with coil clean-outs after each stage to unload solids and fluids from the well. Initial fracture designs were conservative in terms of pad and proppant scheduling which, alongside learnings around operational logistics offshore West of Shetlands and completion design, offer significant optimisations for future hydraulic fractures. Post frac A23 became the highest non-natural fractured producer across Clair. Initially a six-fold production increase was observed with monitoring of transient production ongoing. Tracer analysis confirmed production contribution from all zones. Proving fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Additionally, significant portions of the undeveloped Lower Clair Group to the South of Ph1 comprises lower permeability reservoir with higher viscosity oil and reduced natural fracture presence. Hydraulic fracturing is therefore a crucial completion technique for developing this lower quality reservoir and brings significant value enhancement to the project. Efficient delivery of numerous large fractures in a harsh offshore environment West of Shetlands presents significant challenges. The influence of how the A23 fracturing results and learnings are guiding future hydraulic fracturing concept are detailed, including optimising platform engineering design to facilitate efficient fracturing operations while maintaining the required productivity in this challenging scenario.

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Hydraulic fracturing in an unconventional naturally fractured reservoir: a numerical and experimental study

The APPEA Journal ◽

10.1071/aj10034 ◽

2011 ◽

Vol 51 (1) ◽

pp. 507 ◽

Cited By ~ 1

Author(s):

Mohammad Sarmadivaleh ◽

Vamegh Rasouli ◽

Noufal Kakode Shihab

Keyword(s):

Hydraulic Fracturing ◽

Numerical Models ◽

Interaction Mechanism ◽

Triaxial Stress ◽

Natural Fracture ◽

Particle Flow Code ◽

Filling Material ◽

Fractured Reservoir ◽

Natural Fractures ◽

True Triaxial

Natural fractures play a vital role in the production of low permeability reservoirs when no stimulation techniques are used. The characteristics of natural fractures, together with their pattern that defines how they communicate with each other and to the wellbore, will govern how effectively they can contribute in production enhancement. In most occasions, however, hydraulic fracturing must be used as a remedy to have an economical production rate. Fraccing itself is a complicated process, but would be further complicated when it is practiced in a discontinuous medium. Depending on the properties of the natural fracture(s) and operational condition of the fraccing job, opening, offsetting, crossing or arresting are possible interactions that may happen when an induced fracture reaches a natural discontinuity. In this study, the simplest interaction case with an angle of approach of 90° was studied through both laboratory experiments and numerical modelling. The experiments were carried out under real-triaxial stress conditions using a true-triaxial stress cell (TTSC). Two cement blocks of 20 cm with artificially-made natural fractures were used in this study. The cuts in one sample were filled with weak glue, whereas stiff cement was used in the second sample. The results indicate the importance of interface filling material properties in dominating the interaction mechanism. The numerical models built to simulate these two lab scenarios used particle flow code 2D (PFC2D). The model was tuned and validated against the experimental observations and a good agreement observed between the results of the two approaches.

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Seismic azimuthal anisotropy analysis after hydraulic fracturing

Interpretation ◽

10.1190/int-2013-0013.1 ◽

2013 ◽

Vol 1 (2) ◽

pp. SB27-SB36 ◽

Cited By ~ 11

Author(s):

Kui Zhang ◽

Yanxia Guo ◽

Bo Zhang ◽

Amanda M. Trumbo ◽

Kurt J. Marfurt

Keyword(s):

Hydraulic Fracturing ◽

Anisotropy Field ◽

Horizontal Wells ◽

Horizontal Stress ◽

Azimuthal Anisotropy ◽

Barnett Shale ◽

Natural Fractures ◽

Tight Sandstone ◽

Induced Fractures ◽

Maximum Horizontal Stress

Many tight sandstone, limestone, and shale reservoirs require hydraulic fracturing to provide pathways that allow hydrocarbons to reach the well bore. Most of these tight reservoirs are now produced using multiple stages of fracturing through horizontal wells drilled perpendicular to the present-day azimuth of maximum horizontal stress. In a homogeneous media, the induced fractures are thought to propagate perpendicularly to the well, parallel to the azimuth of maximum horizontal stress, thereby efficiently fracturing the rock and draining the reservoir. We evaluated what may be the first anisotropic analysis of a Barnett shale-gas reservoir after extensive hydraulic fracturing and focus on mapping the orientation and intensity of induced fractures and any preexisting factures, with the objective being the identification of reservoir compartmentalization and bypassed pay. The Barnett Shale we studied has near-zero permeability and few if any open natural fractures. We therefore hypothesized that anisotropy is therefore due to the regional northeast–southwest maximum horizontal stress and subsequent hydraulic fracturing. We found the anisotropy to be highly compartmentalized, with the compartment edges being defined by ridges and domes delineated by the most positive principal curvature [Formula: see text]. Microseismic work by others in the same survey indicates that these ridges contain healed natural fractures that form fracture barriers. Mapping such heterogeneous anisotropy field could be critical in planning the location and direction of any future horizontal wells to restimulate the reservoir as production drops.

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Numerical Simulation of Artificial Fracture Propagation in Shale Gas Reservoirs Based on FPS-Cohesive Finite Element Method

Geofluids ◽

10.1155/2019/9402392 ◽

2019 ◽

Vol 2019 ◽

pp. 1-16 ◽

Cited By ~ 3

Author(s):

Xiaoqiang Liu ◽

Zhanqing Qu ◽

Tiankui Guo ◽

Ying Sun ◽

Zhifeng Shi ◽

...

Keyword(s):

Numerical Simulation ◽

Finite Element ◽

Hydraulic Fracturing ◽

In Situ Stress ◽

Natural Fracture ◽

Natural Fractures ◽

Rock Matrix ◽

Gas Reservoirs ◽

Artificial Fracture

The simulation of hydraulic fracturing by the conventional ABAQUS cohesive finite element method requires a preset fracture propagation path, which restricts its application to the hydraulic fracturing simulation of a naturally fractured reservoir under full coupling. Based on the further development of a cohesive finite element, a new dual-attribute element of pore fluid/stress element and cohesive element (PFS-Cohesive) method for a rock matrix is put forward to realize the simulation of an artificial fracture propagating along the arbitrary path. The effect of a single spontaneous fracture, two intersected natural fractures, and multiple intersected spontaneous fractures on the expansion of an artificial fracture is analyzed by this method. Numerical simulation results show that the in situ stress, approaching angle between the artificial fracture and natural fracture, and natural fracture cementation strength have a significant influence on the propagation morphology of the fracture. When two intersected natural fractures exist, the second one will inhibit the propagation of artificial fractures along the small angle of the first natural fractures. Under different in situ stress differences, the length as well as aperture of the hydraulic fracture in a rock matrix increases with the development of cementation superiority of natural fractures. And with the increasing of in situ horizontal stress differences, the length of the artificial fracture in a rock matrix decreases, while the aperture increases. The numerical simulation result of the influence of a single natural fracture on the propagation of an artificial fracture is in agreement with that of the experiment, which proves the accuracy of the PFS-Cohesive FEM for simulating hydraulic fracturing in shale gas reservoirs.

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